FIG. 1 illustrates a general wellsite system in which the present invention can be employed. The wellsite can be onshore or offshore. In this exemplary system, a borehole 11 is formed in subsurface formations by rotary drilling in a manner that is well known. Embodiments of the invention can also use directional drilling, as will be described hereinafter.
A drill string 12 is suspended within the borehole 11 and has a bottom hole assembly 100 which includes a drill bit 105 at its lower end. The surface system includes platform and derrick assembly 10 positioned over the borehole 11, the assembly 10 including a rotary table 16, kelly 17, hook 18 and rotary swivel 19. The drill string 12 is rotated by the rotary table 16, energized by means not shown, which engages the kelly 17 at the upper end of the drill string. The drill string 12 is suspended from a hook 18, attached to a traveling block (also not shown), through the kelly 17 and a rotary swivel 19 which permits rotation of the drill string relative to the hook. As is well known, a top drive system could alternatively be used.
In the example of this embodiment, the surface system further includes drilling fluid or mud 26 stored in a pit 27 formed at the well site. A pump 29 delivers the drilling fluid 26 to the interior of the drill string 12 via a port in the swivel 19, causing the drilling fluid to flow downwardly through the drill string 12 as indicated by the directional arrow 8. The drilling fluid exits the drill string 12 via ports in the drill bit 105, and then circulates upwardly through the annulus region between the outside of the drill string and the wall of the borehole, as indicated by the directional arrows 9. In this well known manner, the drilling fluid lubricates the drill bit 105 and carries formation cuttings up to the surface as it is returned to the pit 27 for recirculation.
The bottom hole assembly 100 of the illustrated embodiment a logging-while-drilling (LWD) module 120, a measuring-while-drilling (MWD) module 130, a rotary-steerable system and motor, and drill bit 105.
The LWD module 120 is housed in a special type of drill collar, as is known in the art, and can contain one or a plurality of known types of logging tools. It will also be understood that more than one LWD and/or MWD module can be employed, e.g. as represented at 120A. (References, throughout, to a module at the position of 120 can alternatively mean a module at the position of 120A as well.) The LWD module includes capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment. In the present embodiment, the LWD module includes a pressure measuring device.
The MWD module 130 is also housed in a special type of drill collar, as is known in the art, and can contain one or more devices for measuring characteristics of the drill string and drill bit. The MWD tool further includes an apparatus (not shown) for generating electrical power to the downhole system. This may typically include a mud turbine generator powered by the flow of the drilling fluid, it being understood that other power and/or battery systems may be employed. In the present embodiment, the MWD module includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.
One use of the system hereof is in conjunction with controlled steering or “directional drilling.” In this embodiment, a rotary-steerable subsystem 150 (FIG. 1) is provided. Directional drilling is the intentional deviation of the wellbore from the path it would naturally take. In other words, directional drilling is the steering of the drill string so that it travels in a desired direction. Directional drilling is, for example, advantageous in offshore drilling because it enables many wells to be drilled from a single platform. Directional drilling also enables horizontal drilling through a reservoir. Horizontal drilling enables a longer length of the wellbore to traverse the reservoir, which increases the production rate from the well. A directional drilling system may also be used in vertical drilling operation as well. Often the drill bit will veer off of a planned drilling trajectory because of the unpredictable nature of the formations being penetrated or the varying forces that the drill bit experiences. When such a deviation occurs, a directional drilling system may be used to put the drill bit back on course. A known method of directional drilling includes the use of a rotary steerable system (“RSS”). In a RSS, the drill string is rotated from the surface, and downhole devices cause the drill bit to drill in the desired direction. Rotating the drill string greatly reduces the occurrences of the drill string getting hung up or stuck during drilling. Rotary steerable drilling systems for drilling deviated boreholes into the earth may be generally classified as either “point-the-bit” systems or “push-the-bit” systems. In the point-the-bit system, the axis of rotation of the drill bit is deviated from the local axis of the bottom hole assembly in the general direction of the new hole. The hole is propagated in accordance with the customary three point geometry defined by upper and lower stabilizer touch points and the drill bit. The angle of deviation of the drill bit axis coupled with a finite distance between the drill bit and lower stabilizer results in the non-collinear condition required for a curve to be generated. There are many ways in which this may be achieved including a fixed bend at a point in the bottom hole assembly close to the lower stabilizer or a flexure of the drill bit drive shaft distributed between the upper and lower stabilizer. In its idealized form, the drill bit is not required to cut sideways because the bit axis is continually rotated in the direction of the curved hole. Examples of point-the-bit type rotary steerable systems, and how they operate are described in U.S. Patent Application Publication Nos. 2002/0011359; 2001/0052428 and U.S. Pat. Nos. 6,394,193; 6,364,034; 6,244,361; 6,158,529; 6,092,610; and 5,113,953 all herein incorporated by reference. In the push-the-bit rotary steerable system there is usually no specially identified mechanism to deviate the bit axis from the local bottom hole assembly axis; instead, the requisite non-collinear condition is achieved by causing either or both of the upper or lower stabilizers to apply an eccentric force or displacement in a direction that is preferentially orientated with respect to the direction of hole propagation. Again, there are many ways in which this may be achieved, including non-rotating (with respect to the hole) eccentric stabilizers (displacement based approaches) and eccentric actuators that apply force to the drill bit in the desired steering direction. Again, steering is achieved by creating non co-linearity between the drill bit and at least two other touch points. In its idealized form the drill bit is required to cut side ways in order to generate a curved hole. Examples of push-the-bit type rotary steerable systems, and how they operate are described in U.S. Pat. Nos. 5,265,682; 5,553,678; 5,803,185; 6,089,332; 5,695,015; 5,685,379; 5,706,905; 5,553,679; 5,673,763; 5,520,255; 5,603,385; 5,582,259; 5,778,992; 5,971,085 all herein incorporated by reference.
FIG. 2 is a simplified diagram of a logging device, of a type disclosed in U.S. Pat. No. 6,986,282, incorporated herein by reference, for determining downhole pressures including annular pressure, formation pressure, and pore pressure, during a drilling operation, it being understood that other types of pressure measuring LWD tools can also be utilized as the LWD tool 120 or part of an LWD tool suite 120A. The device is formed in a modified stabilizer collar 1200 which has a passage 1215 extending there through drilling fluid. The flow of fluid through the tool creates an internal pressure PI. The exterior of the drill collar is exposed to the annular pressure PA of the surrounding wellbore. The differential pressure δP between the internal pressure PI and the annular pressure PA is used to activate the pressure assemblies 1210. Two representative pressure measuring assemblies are shown at 1210a and 1210b, respectively mounted on stabilizer blades. Pressure assembly 1210a is used to monitor annular pressure in the borehole and/or pressures of the surrounding formation when positioned in engagement with the wellbore wall. In FIG. 2, pressure assembly 1210a is in non-engagement with the borehole wall 1201 and, therefore, may measure annular pressure, if desired. When moved into engagement with the borehole wall 1201, the pressure assembly 1210a may be used to measure pore pressure of the surrounding formation. As also seen in FIG. 2, pressure assembly 1210b is extendable from the stabilizer blade 1214, using hydraulic control 1225, for sealing engagement with a mudcake 1205 and/or the wall 1201 of the borehole for taking measurements of the surrounding formation. The above referenced U.S. Pat. No. 6,986,282 can be referred to for further details. Circuitry (not shown in this view) couples pressure-representative signals to a processor/controller, an output of which is coupleable to telemetry circuitry.
Surveying of boreholes is commonly performed using downhole survey instruments. These instruments typically contain sets of three orthogonal accelerometers and magnetometers which are coupled within a bottom hole assembly (BHA), which is in turn coupled in the drillstring from 20 to 200 feet above the drill bit. These survey instruments are used to measure the direction and magnitude of the local gravitational and magnetic field vectors in order to determine the azimuth and the inclination of the borehole at each survey station within the borehole. Generally, discrete borehole surveys are performed at survey stations along the borehole when drilling is stopped or interrupted to add additional joints or stands of drillpipe to the drillstring at the surface, for example, approximately every 30 or 90 feet.
Rotating produces a generally linear trajectory of the drilled borehole, although there are typically borehole deviations from true linear trajectory due to the effects of gravity, geologic heterogeneities, misalignment between the BHA and the borehole, stiffness of the drillstring and transition effects that occur due to switching from one drilling mode to the other. Drilling while sliding produces a curved trajectory of the drilled borehole generally conforming to an arc. Again, there are typically borehole deviations from true arc configuration of a borehole segment drilled by sliding due to the same factors that cause borehole deviations from linear trajectory with drilling by rotating.
Many factors may combine to unpredictably influence the trajectory of a drilled borehole. It is important to accurately determine the borehole trajectory in order to determine the position of the borehole at any given point of interest and to guide the borehole to its geological objective. “Position,” as that term is used herein in reference to boreholes, indicates the total vertical depth, longitude and latitude of a point of interest. Surveying of a borehole using existing methods involves the intermittent measurement of the earth's magnetic and gravitational fields to determine the azimuth and inclination of the borehole at the BHA under static conditions; that is, while the BHA is stationary. These “static” surveys are generally performed at discrete survey “stations” along the borehole when drilling operations are suspended to make up additional joints or stands of drillpipe into the drillstring. Consequently, the along hole depth or borehole distance between discrete survey stations is generally from 30 or 90 feet or more corresponding to the length of joints or stands of drillpipe added at the surface.
Reliable measurements of the earth's magnetic and gravitational fields are available at the survey stations, and can be used to obtain reliable estimates of the azimuth and inclination of the borehole at the survey stations. Although the azimuth and inclination at a survey station of interest can be determined using measurements of the earth's magnetic and gravitational fields, the true vertical depth cannot be measured directly by tools downhole, and must be determined by other means. The true vertical depth and position of a survey station is determined by mathematically combining the segments of the borehole between discrete survey stations starting with the surface location of the drilling rig and progressing downward to the geologic objective of the borehole. The problem is that undetected borehole variations occurring between discrete survey stations cause substantial errors in calculating the vertical depth and position of a survey station of interest. Undetected borehole variations accumulate as mathematical combination of borehole segments is used to calculate and track borehole vertical depth and position.
The survey instruments that reliably measure the earth's magnetic and gravitational fields at survey stations can also be used to obtain measurements of the earth's magnetic and gravitational fields. Drilling operations, as that term is used herein, means that the drill bit is being rotated against rock. Literally thousands of measurements of the earth's magnetic and gravitational fields can be obtained for each borehole segment using existing survey instruments. Successive measurements of the earth's magnetic and gravitational fields during drilling operations may be separated by only fractions of a second or thousandths of a meter and, in light of the relatively slow rate of change of the magnetic and gravitational fields in drilling a borehole, these measurements are continuous for all practical analyses. For this reason, the determination of azimuth and inclination of a borehole from measurements of the earth's magnetic and gravitational fields made are referred to herein as “continuous” measurements.
One or more survey stations may be generated using “discrete” or “continuous” measurement modes. Generally, discrete or “static” wellbore surveys are performed by creating survey stations along the wellbore when drilling is stopped or interrupted to add additional joints or stands of drillpipe to the drillstring at the surface. Continuous wellbore surveys relate to a multitude of measurements obtained while drill pipe is in motion using the survey instruments.
Known survey techniques as used herein encompass the utilization of a variety of methodologies to estimate wellbore position, such as using sensors, magnetometers, accelerometers, gyroscopes, measurements of drill pipe length or wireline depth, Measurement While Drilling (“MWD”) tools, Logging While Drilling (“LWD”) tools, wireline tools, seismic data, and the like.
Existing wellbore survey computation techniques use various methodologies, including the Tangential method, Balanced Tangential method, Average Angle method, Mercury method, Differential Equation method, cylindrical Radius of Curvature method and the Minimum Radius of Curvature method, to model the trajectory of the wellbore segments between survey stations. For each methodology, there is a trade-off between the relative complexity/simplicity of the calculation required to complete the survey, and the resulting resolution and degree of accuracy.
One problem is that the violent crushing and grinding of the drill bit against rock at the bottom of the borehole, the irregular interaction of the drillstring with the walls of the borehole, and even the constantly changing stresses in the connections between joints of drillpipe, all present during drilling operations, combine to contribute noise, shock and vibrations that severely contaminates continuously obtained measurements of the earth's magnetic and gravitational fields to the extent that this data is not useful in reliably determining the azimuth and inclination of the borehole at points between survey stations. If continuously obtained magnetic and gravitational field data could be effectively used, borehole deviations occurring between survey stations could be detected and accounted for in calculating and tracking the depth of the borehole.
Various considerations have brought about an ever-increasing need for more precise wellbore surveying techniques. More accurate survey information and true vertical depth is necessary at high resolution in measured depth to ensure the avoidance of well collisions (or alternatively, ensure intersection of wells) and the successful penetration of geological targets.
Despite the development and advancement of wellbore survey techniques in wellbore operations, there remains a need to provide highly accurate surveys and/or to use such data to perform additional functions. It is desirable that such techniques improve the efficiency of the drilling operation, including reducing rig time lost to stopping drilling. It is also desirable that such a system provide one or more of the following, among others: improved position accuracy, less wear on wellbore equipment, a smoother wellbore path, reduced lost in hole, modeling and/or predicting bit location, autonomous, semi-autonomous and/or closed loop drilling and correlating survey data with other wellbore data, and real time survey data.
As stated, it is desirable to save valuable drilling time, especially in low data rates conditions, where the survey transmission can take several minutes to the surface and some drillers cannot proceed without an accurate stationary survey. Such lost drilling time is cumulative and can add up to a substantial cost with new offshore rigs costs approaching million dollars a day.